During the process of drilling a wellbore, such as an oil well, individual lengths of relatively large diameter metal tubulars are typically secured together to form a casing string or liner that is positioned within each section of the wellbore. Each of the casing strings may be hung from a wellhead installation near the surface. Alternatively, some of the casing strings may be in the form of liner strings that extend from near the setting depth of a previous section of casing. In this case, the liner string will be suspended from the previous section of casing on a liner hanger. The casing strings are usually comprised of a number of joints or segments, each being on the order of forty feet long, connected to one another by threaded connections or other connection means. These connections are typically metal pipes, but may also be non-metal materials such as composite tubing. This casing string is used to increase the integrity of the wellbore by preventing the wall of the hole from caving in. In addition, the casing string prevents movement of fluids from one formation to another formation through which the wellbore passes.
Conventionally, each section of the casing string is cemented within the wellbore before the next section of the wellbore is drilled. Accordingly, each subsequent section of the wellbore must have a diameter that is less than the previous section. For example, a first section of the wellbore may receive a surface (or conductor) casing string having a 20-inch diameter. The next several sections of the wellbore may receive intermediate (or protection) casing strings having 16-inch, 13⅜-inch and 9⅝-inch diameters, respectively. The final sections of the wellbore may receive production casing strings having 7-inch and 4½-inch diameters, respectively. When the cementing operation is completed and the cement sets, there is a column of cement in the annulus described by the outside surface of each casing string.
Subterranean zones penetrated by well bores are commonly sealed by hydraulic cement compositions. In this application, pipe strings such as casings and liners are cemented in well bores using hydraulic cement compositions. In performing these primary cementing operations, a hydraulic cement composition is pumped into the annular space described by the walls of a well bore and the exterior surfaces of a pipe string disposed therein. The cement composition is permitted to set in the annular space to form an annular sheath of hardened substantially impermeable cement which supports and positions the pipe string in the well bore and seals the exterior surfaces of the pipe string to the walls of the well bore. Hydraulic cement compositions are also utilized in a variety of other cementing operations, such as sealing highly permeable zones or fractures in subterranean zones, plugging cracks or holes in pipe strings and the like.
Casing assemblies comprising more than one casing string describe one or more annular volumes between adjacent concentric casing strings within the wellbore. Normally, each annular volume is filled, at least to some extent, with the fluid which is present in the wellbore when the casing string is installed. In a deep well, the quantities of fluid within the annular volume (i.e., the annular fluid) may be significant. Each annulus 1 inch thick by 5000 feet long would contain roughly 50,000 gallons, depending on the diameter of the casing string.
In oil and gas wells it is not uncommon that a section of formation must be isolated from the rest of the well. This is typically achieved by bringing the top of the cement column from the subsequent string up inside the annulus above the previous casing shoe. While this isolates the formation, bringing the cement up inside the casing shoe effectively blocks the safety valve provided by nature's fracture gradient. Instead of leaking off at the shoe, any pressure build up will be exerted on the casing, unless it can be bled off at the surface. Most land wells and some offshore platform wells are equipped with wellheads that provide access to every casing annulus and an observed pressure increase can be quickly bled off. On the other hand, most subsea wellhead installations do not provide access to the casing annuli and a sealed annulus may be created. Because the annulus is sealed, the internal pressure can increase significantly in reaction to an increase in temperature.
The fluids in the annular volume during installation of the casing strings will generally be at or near the ambient temperature of the seafloor. When the annular fluid is heated, it expands and a substantial pressure increase may result. This condition is commonly present in all producing wells, but is most evident in deep water wells. Deep water wells are likely to be vulnerable to annular pressure build up because of the cold temperature of the displaced fluid, in contrast to elevated temperature of the production fluid during production. The temperature of the fluid in the annular volume when it is sealed will generally be the ambient temperature, which may be in the range of from 0° F. to 100° F. (for example 34° F.), with the lower temperatures occurring most frequently in subsea wells with a considerable depth of water above the well. During production from the reservoir, produced fluids pass through the production tubing at significantly higher temperatures. Temperatures in the range of 50° F. to 300° F. are expected, and temperatures in the range of 125° F. to 250° F. are frequently encountered.
The relatively high temperature of the produced fluids increases the temperature of the annular fluid between the casing strings, and increases the pressure against each of the casing strings. Conventional liquids which are used in the annular volume expand with temperature at constant pressure; in the constant volume of the annular space, the increased fluid temperature results in significant pressure increases. Aqueous fluids, which are substantially incompressible, could increase in volume by upwards of 5% during the temperature change from ambient conditions to production conditions at constant pressure. At constant volume, this increase in temperature may result in pressure increases up to on the order of 10,000 psig. The increased pressure significantly increases the chances that the casing string fails, with catastrophic consequences to the operation of the well.
What is needed is a method for replacing at least a portion of the conventional fluid within the annular volume with a fluid system which decreases in specific volume as temperature of the fluid is increased. Also needed are ways to control any build up of static charge within the fluid system in the annular volume to decrease the risk of sparking.
The annular pressure build up (APB) problem is well known in the petroleum drilling/recovery industry. See: B. Moe and P. Erpelding, “Annular pressure buildup: What it is and what to do about it,” Deepwater Technology, p. 21-23, August (2000), and P. Oudeman and M. Kerem, “Transient behavior of annular pressure buildup in HP/HT wells,” J. of Petroleum Technology, v. 18, no. 3, p. 58-67 (2005). Several potential solutions have been previously reported: A. injection of nitrogen-foamed cement spacers as described in R. F. Vargo, Jr., et. al., “Practical and Successful Prevention of Annular Pressure Buildup on the Marlin Project,” Proceedings—SPE Annual Technical Conference and Exhibition, p. 1235-1244, (2002), B. vacuum insulated tubing as described in J. H. Azzola, et. al., “Application of Vacuum Insulated Tubing to Mitigate Annular Pressure Buildup,” Proceedings—SPE Annual Technical Conference and Exhibition, p. 1899-1905 (2004), C. crushable foam spacer as described in C. P. Leach and A. J. Adams, “A New Method for the Relief of Annular Heat-up Pressure,” in proceedings, —SPE Annual Technical Conference and Exhibition, p. 819-826, (1993), D. cement shortfall, full-height cementation, preferred leak path or bleed port, enhanced casing (stronger), and use of compressible fluids as described in R. Williamson et. al., “Control of Contained-Annulus Fluid Pressure Buildup,” in proceedings, SPE/IADC Drilling Conference paper Number 79875 (2003), and E. use of a burst disk assembly, as described by J. Staudt in U.S. Pat. No. 6,457,528 (2002) and U.S. Pat. No. 6,675,898 (2004). These prior art examples, although potentially useful, do not provide full protection against the APB problem due to either difficulties in implementation or prohibitory costs, or both. Our invention is relatively easy to implement and cost effective.